Jetting tool

ABSTRACT

A jetting tool includes a tubular housing having: couplings formed at each longitudinal end thereof, and one or more ports formed through a wall thereof and in fluid communication with an upper portion of a bore of the housing. The jetting tool further includes a valve mechanism isolating the housing bore upper portion from a lower portion thereof in a closed position and operable to an open position where the valve mechanism provides fluid communication between the housing bore portions.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention generally relates to a jetting tool.

2. Description of the Related Art

In well construction and completion operations, a wellbore is formed to access hydrocarbon-bearing formations (e.g., crude oil and/or natural gas) by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is temporarily hung from the surface of the well. A cementing operation is then conducted in order to fill the annulus with cement. The casing string is cemented into the wellbore by circulating cement into the annulus defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.

Deep water offshore drilling operations are typically carried out by a mobile offshore drilling unit (MODU), such as a drill ship or a semi-submersible, having the drilling rig aboard and often make use of a marine riser extending between the wellhead of the well that is being drilled in a subsea formation and the MODU. The marine riser is a tubular string made up of a plurality of tubular sections that are connected in end-to-end relationship. The riser allows return of the drilling mud with drill cuttings from the hole that is being drilled. Also, the marine riser is adapted for being used as a guide for lowering equipment (such as a drill string carrying a drill bit) into the hole.

SUMMARY OF THE INVENTION

The present invention generally relates to a jetting tool. In one embodiment, a jetting tool includes a tubular housing having: couplings formed at each longitudinal end thereof, and one or more ports formed through a wall thereof and in fluid communication with an upper portion of a bore of the housing. The jetting tool further includes a valve mechanism isolating the housing bore upper portion from a lower portion thereof in a closed position and operable to an open position where the valve mechanism provides fluid communication between the housing bore portions.

In another embodiment, a method for deploying a bearing assembly to a receiver includes deploying a running assembly to the receiver. The running assembly includes: the bearing assembly, a running tool carrying the bearing assembly, and a jetting tool connected to the running tool. The method further includes: washing an inner surface of the receiver using the jetting tool; latching the bearing assembly to the washed inner surface of the receiver; and releasing the bearing assembly from the running tool.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIGS. 1A and 1B illustrate an offshore drilling system deploying a protective sleeve to a docking station of a rotating control device, according to one embodiment of the present invention. FIG. 1C illustrates washing of a latch of the docking station using a jetting tool during deployment of the protective sleeve before running a drill string of the drilling system.

FIG. 2A illustrates the jetting tool in a washing mode. FIG. 2B illustrates the jetting tool in a well control mode.

FIGS. 3A-3C illustrate the offshore drilling system in an overbalanced drilling mode.

FIGS. 4A-4C illustrate removal of a stand from the drill string.

FIGS. 5A-5D illustrate addition of the protective sleeve running tool to the drill string. FIGS. 5E-5G illustrate removal of the protective sleeve from the docking station.

FIG. 6 illustrates stabbing of a bearing assembly running tool and jetting tool into a bearing assembly of the rotating control device to form a running assembly.

FIGS. 7A-7D illustrate addition of the running assembly string to the drill string. FIG. 7E illustrates washing of the docking station latch using the jetting tool. FIGS. 7F and 7G illustrate installation of the bearing assembly into the docking station.

FIGS. 8A and 8B illustrate the offshore drilling system in a managed pressure drilling mode.

DETAILED DESCRIPTION

FIGS. 1A and 1B illustrate an offshore drilling system 1 deploying a protective sleeve 61 (see also FIG. 1C) to a receiver, such as docking station 26, of a rotating control device (RCD) 60 (FIG. 7G), according to one embodiment of the present invention. The drilling system 1 may include a mobile offshore drilling unit (MODU) 1 m, such as a semi-submersible, a drilling rig 1 r, a fluid handling system 1 h, a fluid transport system 1 t, and a pressure control assembly (PCA) 1 p (FIG. 3B). The MODU 1 m may carry the drilling rig 1 r and the fluid handling system 1 h aboard and may include a moon pool, through which operations are conducted. The semi-submersible MODU 1 m may include a lower barge hull which floats below a surface (aka waterline) 2 s of sea 2 and is, therefore, less subject to surface wave action. Stability columns (only one shown) may be mounted on the lower barge hull for supporting an upper hull above the waterline 2 s. The upper hull may have one or more decks for carrying the drilling rig 1 r and fluid handling system 1 h. The MODU 1 m may further have a dynamic positioning system (DPS) (not shown) and/or be moored for maintaining the moon pool in position over a subsea wellhead 50 (FIG. 3B).

Alternatively, the MODU 1 m may be a drill ship. Alternatively, a fixed offshore drilling unit or a non-mobile floating offshore drilling unit may be used instead of the MODU 1 m. Alternatively, the wellhead 50 may be located adjacent to the waterline 2 s and the drilling rig 1 r may be a located on a platform adjacent the wellhead. Alternatively, the drilling system 1 may be used for drilling a subterranean (aka land based) wellbore and the MODU 1 m may be omitted.

The drilling rig 1 r may include a derrick 3 having a rig floor 4 at its lower end having an opening corresponding to the moonpool. The drilling rig 1 r may further include a rail 88 (FIG. 4A) extending from the rig floor 4 toward a crown block 8 of the rig 1 r. The drilling rig 1 r may further include a top drive 5. The top drive 5 may include an extender 5 x (FIG. 4C), motor 5 m (FIG. 4A), an inlet 5 i, a gear box 5 g, a swivel 5 r, a quill 5 q, a trolley 5 t, a pipe hoist 5 b,e, and a backup wrench 5 w. The top drive motor 5 m may be electric or hydraulic and have a rotor and stator. The motor 5 m may be operable to rotate the rotor relative to the stator which may also torsionally drive 13 the quill 5 q via one or more gears (not shown) of the gear box 5 g. The quill 5 q may have a coupling (not shown), such as splines, formed at an upper end thereof and torsionally connecting the quill to a mating coupling of one of the gears. Housings of the motor 5 m, swivel 5 r, gear box 5 g, and backup wrench 5 w may be connected to one another, such as by fastening, so as to form a non-rotating frame. The top drive 5 may further include an interface (not shown) for receiving power and/or control lines.

The extender 5 x may torsionally connect the frame to the trolley 5 t and include one or more arms and an actuator, such as a piston and cylinder assembly. The extender arms may pivotally connect to the frame and trolley 5 t such that operation of the extender actuator may horizontally extend or retract the frame (and rotating components) relative to the trolley and rail 88. The trolley 5 t may ride along the rail 88, thereby torsionally restraining the frame while allowing vertical movement of the top drive 5 with a travelling block 6 of the rig 1 r. The traveling block 6 may be connected to the frame, such as by fastening to suspend the top drive 5 from the derrick 3. Alternatively, the top drive 5 may include a becket for receiving a hook of the traveling block 6.

The swivel 5 r may include one or more bearings (not shown) for longitudinally and rotationally supporting rotation of the quill 5 q relative to the frame. The inlet 5 i may have a coupling for connection to a Kelly hose 17 h and provide fluid communication between the Kelly hose and a bore of the quill 5 q. The quill 5 q may have a coupling, such as a threaded pin, formed at a lower end thereof for connection to a mating coupling, such as a threaded box, of a work string 86 or drill string 10 (FIG. 3A). The pipe hoist 5 b,e may include an elevator 5 e, one or more links 5 b pivotally connecting the elevator to the top drive frame, and a link tilt (not shown), such as a piston and cylinder assembly, for horizontally extending or retracting the elevator relative to the frame. The elevator 5 e may be manually opened and closed or the pipe hoist 5 b,e may include an actuator (not shown) for opening and closing the elevator. Additionally, the top drive 5 may further include a (first) thread compensator (not shown).

The backup wrench 5 w may include a tong, a telescoping arm, an arm actuator (not shown), and a tong actuator (not shown). The telescoping arm may torsionally connect the tong to the frame while allowing the arm actuator to longitudinally move the tong relative to the frame. The tong may include a pair of jaws and the tong actuator may radially move one of the jaws radially toward or away from the other jaw. The arm actuator may also operate as a second thread compensator while making up a threaded connection between the quill 5 q and the work string 86 or drill string 10.

The traveling block 6 may be supported by wire rope 7 connected at its upper end to the crown block 8. The wire rope 7 may be woven through sheaves of the blocks 6, 8 and extend to drawworks 9 for reeling thereof, thereby raising or lowering the traveling block 6 relative to the derrick 3. A top of the work string 86 or drill string 10 may be connected to the quill 5 q, such as by a threaded connection. The drilling rig 1 r may further include a drill string compensator (not shown) to account for heave of the MODU 1 m. The drill string compensator may be disposed between the traveling block 6 and the top drive 5 (aka hook mounted) or between the crown block 8 and the derrick 3 (aka top mounted).

The fluid transport system it may include the drill string 10, an upper marine riser package (UMRP) 20, a marine riser 25, and one or more auxiliary lines, such as a booster line 27 and a choke line 28. The riser 25 may extend from the PCA 1 p to the MODU 1 m and may connect to the MODU via the UMRP 20. The UMRP 20 may include a diverter 21, a flex joint 22, a slip (aka telescopic) joint 23, a tensioner 24, and the RCD docking station 26. A lower end of the RCD docking station 26 may be connected to an upper end of the riser 25, such as by a flanged connection. The slip joint 23 may include an outer barrel connected to an upper end of the RCD docking station 26, such as by a flanged connection, and an inner barrel connected to the flex joint 22, such as by a flanged connection. The outer barrel may also be connected to the tensioner 24, such as by a tensioner ring.

The flex joint 22 may also connect to the diverter 21, such as by a flanged connection. The diverter 21 may also be connected to the rig floor 4, such as by a bracket. The slip joint 23 may be operable to extend and retract in response to heave of the MODU 1 m relative to the riser 25 while the tensioner 24 may reel wire rope in response to the heave, thereby supporting the riser 25 from the MODU 1 m while accommodating the heave. The flex joints 23, 43 (FIG. 3B) may accommodate respective horizontal and/or rotational (aka pitch and roll) movement of the MODU 1 m relative to the riser 25 and the riser relative to the PCA 1 p. The riser 25 may have one or more buoyancy modules (not shown) disposed therealong to reduce load on the tensioner 24.

The docking station 26 may be convertible between an idle mode (FIG. 3A) and an operating mode (FIG. 8A). The docking station 26 may be submerged adjacent the waterline 2 s. The RCD 60 may include the docking station 26 and a bearing assembly 70 (FIG. 6). The docking station 26 may include a housing 62, a latch 63, and an interface 64. The RCD housing 62 may be tubular and have one or more sections 62 a-c connected together, such as by flanged connections. The RCD housing may have one or more fluid ports formed through a lower housing section 62 c and the docking station 26 may include a connection, such as a flanged outlet 65, fastened to one of the ports.

The latch 63 may include a hydraulic actuator, such as a piston 63 p, one or more (two shown) fasteners, such as dogs 63 d, and a body 63 b. The latch body 63 b may be connected to the housing 62, such as by a threaded connection. A piston chamber may be formed between the latch body 63 b and a mid housing section 62 b. The latch body 63 b may have openings formed through a wall thereof for receiving the respective dogs 63 d. The latch piston 63 p may be disposed in the chamber and may carry seals isolating an upper portion of the chamber from a lower portion of the chamber. A cam surface may be formed on an inner surface of the piston 63 p for radially displacing the dogs 63 d. The latch body 63 b may further have a landing shoulder formed in an inner surface thereof for receiving the protective sleeve 61 or the bearing assembly 70.

Hydraulic passages may be formed through the mid housing section 62 b and may provide fluid communication between the interface 64 and respective portions of the hydraulic chamber for selective operation of the piston 63 p. An RCD umbilical 19 u may have hydraulic conduits and may provide fluid communication between the RCD interface 64 and a hydraulic power unit (HPU) 32 h via hydraulic manifold 32 m. The RCD umbilical 19 u may further have an electric cable for providing data communication between a control console 35 c and the RCD interface 64 via a programmable logic controller (PLC) 35 p.

Alternatively, the latch 63 may include a spring instead of or in addition to one of the hydraulic ports. Alternatively, the docking station 26 may be located above the waterline 2 s and/or along the UMRP 20 at any other location besides a lower end thereof. Alternatively, the docking station 26 may be assembled as part of the riser 25 at any location therealong or as part of the PCA 1 p.

The fluid handling system 1 h may include a drilling fluid tank 15, a supply line 17, one or more shutoff valves 18 a-h, an RCD return line 19 r, a diverter return line 29, a mud pump 30, the HPU 32 h, the hydraulic manifold 32 m, a cuttings separator, such as shale shaker 33, a pressure gauge 34, the control console 35 c, the PLC 35 p, a return bypass spool 36 r, a supply bypass spool 36 s, a wash tank 37, a wash pump 38, and a wash line 39.

A first end of the return line 29 may be connected to an outlet of the diverter 21 and a second end of the return line may be connected to the inlet of the shaker 33. A lower end of the RCD return line 19 r may be connected to the RCD outlet 65 and an upper end of the return line may have shutoff valve 18 c and be blind flanged. An upper end of the return bypass spool 36 r may be connected to the shaker inlet and a lower end of the return bypass spool may have shutoff valve 18 b and be blind flanged. A transfer line 16 may connect an outlet of the fluid tank 15 to the inlet of the mud pump 30.

The supply line 17 may include a header 17 e, a standpipe 17 p, and a Kelly hose 17 h. A lower end of the header 17 e may be connected to the outlet of the mud pump 30. The standpipe 17 p may connect an upper end of the header 17 e to the Kelly hose 17 h. The Kelly hose 17 h may connect the standpipe 17 p to the top drive inlet 5 i. The pressure gauge 34 and mud pump shutoff valve 18 f may be assembled as part of the header 17 e. A first end of the supply bypass spool 36 s may be connected to the header lower end a second end of the bypass spool may be connected to the header upper end and may each be blind flanged. The shutoff valves 18 d,e may be assembled as part of the supply bypass spool 36 s. The wash tank 37 may be connected to an inlet of the wash pump 38. A lower end of the wash line 39 may be connected to an outlet of the wash pump 38 and an upper end of the wash line 39 may be connected to the header 17 e. The wash shutoff valve 18 g may be assembled as part of the header 17 e. The shutoff valve 18 h may also be assembled as part of the header 17 e.

FIG. 1C illustrates washing of a latch of the docking station using a jetting tool 100 during deployment of the protective sleeve 61 before running the drill string 10. The protective sleeve 61 may be installed in the docking station 26 to protect the latch 63 while drilling in the overbalanced mode. In order to deploy the protective sleeve 61, a bottom assembly of the work string 86 may be assembled using an offline stand builder (OSB) (not shown) of the drilling rig 1 r. The bottom assembly may include the protective sleeve 61, protective sleeve running tool (PSRT) 83, a jetting tool 100, and a shoe 89. Alternatively, the top drive 5 and a mouse hole (not shown) of the drilling rig 1 r may be used to assemble the bottom assembly.

The protective sleeve 61 may have a landing shoulder formed at an outer surface thereof, a catch profile formed in an outer surface thereof, and may carry one or more seals on an outer surface thereof. The catch profile may be a groove for receiving the latch dogs 63 d, thereby connecting the protective sleeve 61 to the docking station 26. The protective sleeve 61 may also have a latch profile, such as one or more J-slots, formed in an upper end thereof for connection to the PSRT 83.

The PSRT 83 may include a mandrel 84 and a latch 85. The mandrel 84 may have couplings formed at each longitudinal end thereof, such as a threaded pin formed at a lower end thereof and a threaded box formed at an upper end thereof, for assembly as part of the work string 86. The latch 85 may have a body 85 b and one or more fasteners, such as lugs 85 f, extending from an outer surface of the body. The latch body 85 b may be connected to the mandrel 84, such as by a threaded connection. Each lug 85 f may be operable to interact with the respective J-slots to connect the PSRT 83 to the protective sleeve 61.

The bottom assembly may be assembled by connecting the shoe 89 to the jetting tool 100 and connecting the jetting tool to the PSRT 83. The interconnected shoe 89, jetting tool 100, and PSRT 83 may then be stabbed into the protective sleeve 61 and oriented engage the lugs 85 f with the respective J-slots. During stabbing, the lugs 85 f may be engaged with the J-slots, the PSRT 83 lowered to move the lugs along the J-slots, rotated across the J-slots, and then raised to seat the lugs at a closed end of the J-slots. Once the bottom assembly has been connected together, it may be racked for receipt by the top drive 5.

The top drive 5 may then add stands 10 s of drill pipe 10 p to the work string 86 until the jetting tool 100 arrives at the docking station latch 63. The wash pump 38 may then be operated to inject wash fluid 14 w down the work string 86 to the jetting tool 100. The jetting tool 100 may discharge the wash fluid 14 w into the latch 63 to flush any debris therefrom which may otherwise obstruct landing of the protective sleeve 61. The wash fluid 14 w and entrained debris may return to the MODU 1 m via the UMRP 20 and be discharged at the diverter outlet to the shaker 33. The work string 86 may be reciprocated during washing of the latch 63. Once the latch 63 has been washed, the work string 86 may be further lowered until the landing shoulder of the protective sleeve 61 seats onto the landing shoulder of the latch body 63 b. A technician (not shown) may instruct the PLC 35 p (via the console 35 c) to operate the latch piston 63 p by supplying hydraulic fluid from the HPU 32 h and manifold 32 m to the latch chamber via the RCD umbilical 19 u, thereby radially moving the latch dogs 63 d inward to engage the first catch profile of the protective sleeve 61 (FIG. 3A). The work string 86 may then be rotated by the top drive 5 and raised to disengage the lugs 85 f from the J-slots, thereby freeing the work string 86 from the protective sleeve 61. The work string 86 may then be retrieved to the MODU 1 m.

Alternatively, the bottom assembly (minus the shoe 89) may be deployed using the drill string 10 instead of the workstring 86, as discussed below for deploying the bearing assembly 70.

FIG. 2A illustrates the jetting tool 100 in a washing mode. FIG. 2B illustrates the jetting tool 100 in a well control mode. The jetting tool 100 may include a housing 101 and a valve mechanism 112. The housing 101 may be tubular and have a bore formed therethrough. The housing 101 may have couplings 102 b,p formed at each longitudinal end thereof, such as a threaded pin 102 p formed at a lower end thereof and a threaded box 102 b formed at an upper end thereof, for assembly as part of the work string 86 or drill string 10. The housing 101 may have one or more flow ports 103 a-105 b formed through a wall thereof and in fluid communication with the bore.

The flow ports 103 a-105 b may include one or more radial ports 103 a-c, one or more upwardly inclined ports 104 a,b, and one or more downwardly inclined ports 105 a,b. The jetting tool 100 may further include a nozzle 107 disposed in each flow port. Each nozzle 107 may have a (outwardly) converging flow passage formed therethrough and be made from an erosion resistant material. The nozzle material may be a metal, alloy, or composite, such as tool steel, ceramic, or cermet. Each flow port 103 a-105 b of the housing 101 may form a shoulder for receiving the respective nozzle 107 and have a catch profile, such as a groove, formed therein for receiving a fastener, such as split ring 108, thereby connecting the nozzles to the housing by entrapment between the shoulder and the split ring. Each flow port 103 a-105 b of the housing 101 may further have a groove formed therein for receiving a seal 109 to isolate the housing-nozzle interface. Alternatively, each nozzle 107 may be threaded or bonded into the respective flow port 103 a-105 b.

The jetting tool 100 may further include a stop 106. The stop 106 may include one or more fasteners, such as screws. Each screw may have a thread formed on an outer surface, a head, and a shank and may be disposed in a respective threaded socket 110 formed through a wall of the housing 101. The shank of each screw may protrude into the housing bore. Alternatively, the stop 106 may be a split ring or the housing 101 may include two sections and the stop may be formed in an inner surface of the upper section.

The valve mechanism 112 may include a piston 113, a frangible fastener, such as a shear ring 114, and a valve seat formed in an inner surface of the housing 101. The valve seat may include an upper shoulder 111 u, a mid shoulder 111 b, and a lower flare 111 b. The valve seat may further include a polished bore receptacle formed between the shoulders 111 u,b.

The piston 113 may have a sleeve portion 113 s and a solid nose portion 113 n. A flow passage may formed through the piston 113 and have a bore portion formed along the sleeve portion 113 s and a ported portion formed adjacent an interface between the sleeve and nose portion 113 n. The ported portion may include one or more downwardly inclined ports 115 a-c formed through a wall of the sleeve portion 113 s. The piston 113 may have an upper groove 118 formed in an outer surface of the sleeve portion 113 s and mid and lower grooves formed in an outer surface of the sleeve portion. A lip of the shear ring 114 may be disposed in the upper groove 118, thereby connecting the shear ring and the piston 113. The mid and lower grooves may straddle the piston ports 115 a-c and each may carry a respective seal 117 u,b. The piston 113 may further have an upper shoulder 116 u and a lower shoulder 116 b formed in an outer surface of the sleeve portion 113 s. A recessed track may be formed between the piston shoulders 116 u,b.

The piston 113 may be longitudinally movable relative to the housing 101 between an open position (FIG. 2B) and a closed position (FIG. 2A). The piston 113 may be restrained against downward movement in the closed position by engagement of a base of the shear ring 114 with the upper housing shoulder 111 u and restrained against upward movement relative to the housing by the stop 106, thereby being bidirectionally closed. In the closed position, the piston seals 117 u,b may engage the polished bore receptacle of the housing 101 to close the ports 115 a-c. Closure of the ports 115 a-c in cooperation with the solid piston nose 113 n may isolate a lower portion of the housing bore from an upper portion of the housing bore.

During washing of the latch 63, the wash fluid 14 w may exert a downward pressure force on the piston nose 113 n due to pressure differential across the nozzles 107. The pressure differential may correspond to a flow rate of the wash fluid 14 w discharged by the wash pump 38. The shear ring 114 may have a shear strength sufficient to withstand the pressure force corresponding to a maximum pressure capability and/or flow rate of the wash pump 38. Should a well control event occur during installation of the protective sleeve 61 (using the drill string 10) or bearing assembly 70, the jetting sub 100 may be shifted into well control mode by closing shutoff valve 18 g, opening shutoff valve 18 f, and starting the mud pump 30. The mud pump 30 may then pump drilling fluid 14 d down the work string 86 at a flow rate greater than or substantially greater than (i.e., double or more) the wash flow rate, thereby exerting a correspondingly greater pressure force on the piston nose portion 113 n and fracturing the shear ring 114.

Fracture of the shear ring 114 may free the piston 113 to be pushed downward by the increased pressure force. The piston 113 may travel downward relative to the housing 101 until the lower piston shoulder 116 b seats against the mid housing shoulder 111 m. The piston track may accommodate the downward movement while trapping a base portion of the shear ring 114. A stroke length of the downward movement may be sufficient to move the piston ports 115 a-c out of the polished bore receptacle and into fluid communication with a lower flared portion of the housing bore, thereby opening the piston flow passage. The drilling fluid 14 d may then be free to travel through the jetting tool 100 (via an upper portion of the housing bore, the piston flow passage, and the flared portion of the housing bore), and down a bore of the drill pipe 10 p (disposed below the jetting tool 100), through a bottomhole assembly (BHA) 10 b of the drill string 10, and into the wellbore 55 for addressing the well control event. Radial leakage of the drilling fluid 14 d through the nozzles 107 may be insignificant relative to the longitudinal flow through the jetting tool 100.

FIGS. 3A-3C illustrate the offshore drilling system 1 in an overbalanced drilling mode. Once the protective sleeve 61 has been installed into the docking station 26, overbalanced drilling of the lower formation 54 b may commence. Shutoff valve 18 g may be closed and shutoff valve 18 f may be opened to bring the mud pump 30 online. The drill string 10 may be deployed from the rig 1 r and into the wellbore 55.

The drill string 10 may include the BHA 10 b and joints of the drill pipe 10 p connected together, such as by threaded couplings. The BHA 10 b may be connected to the drill pipe 10 p, such as by a threaded connection, and include a drill bit 12 and one or more drill collars 11 connected thereto, such as by a threaded connection. The drill bit 12 may be rotated 13 by the top drive 5 via the drill pipe 10 p and/or the BHA 10 b may further include a drilling motor (not shown) for rotating the drill bit. The BHA 10 b may further include an instrumentation sub (not shown), such as a measurement while drilling (MWD) and/or a logging while drilling (LWD) sub.

The PCA 1 p may be connected to a wellhead 50 located adjacent to a floor 2 f of the sea 2. A conductor string 51 may have been driven into the seafloor 2 f. The conductor string 51 may include a housing and joints of conductor pipe connected together, such as by threaded connections. Once the conductor string 51 was set, the subsea wellbore 55 may have been drilled into the seafloor 2 f and a casing string 52 deployed into the wellbore. The casing string 52 may include a wellhead housing and joints of casing connected together, such as by threaded connections. The wellhead housing may have been landed in the conductor housing during deployment of the casing string 52. The casing string 52 may have been cemented 53 into the wellbore 55. The casing string 52 may extend to a depth adjacent a bottom of an upper formation 54 u. The upper formation 54 u may be non-productive and a lower formation 54 b may be a hydrocarbon-bearing reservoir. Alternatively, the lower formation 54 b may be environmentally sensitive, such as an aquifer, or unstable. Although shown as vertical, the wellbore 55 may include a vertical portion and a deviated, such as horizontal, portion.

The PCA 1 p may include a wellhead adapter 40 b, one or more flow crosses 41 u,m,b, one or more blow out preventers (BOPS) 42 a,u,b, a lower marine riser package (LMRP), one or more accumulators 44, and an LMRP receiver 46. The LMRP may include a control pod 48, a flex joint 43, and a connector 40 u. The wellhead adapter 40 b, flow crosses 41 u,m,b, BOPS 42 a,u,b, LMRP receiver 46, connector 40 u, and flex joint 43, may each include a housing having a longitudinal bore therethrough and may each be connected, such as by flanges, such that a continuous bore is maintained therethrough. The bore may have drift diameter, corresponding to a drift diameter of the wellhead 50.

Each of the connector 40 u and wellhead adapter 40 b may include one or more fasteners, such as dogs, for fastening the LMRP to the BOPS 42 a,u,b and the PCA 1 p to an external profile of the wellhead housing, respectively. Each of the connector 40 u and wellhead adapter 40 b may further include a seal sleeve for engaging an internal profile of the respective LMRP receiver 46 and wellhead housing. Each of the connector 40 u and wellhead adapter 40 b may be in electric or hydraulic communication with the control pod 48 and/or further include an electric or hydraulic actuator and an interface, such as a hot stab, so that a remotely operated subsea vehicle (ROV) (not shown) may operate the actuator for engaging the dogs with the external profile.

The LMRP may receive a lower end of the riser 25 and connect the riser to the PCA 1 p. The control pod 48 may be in electric, hydraulic, and/or optical communication with a rig controller (not shown) onboard the MODU 1 m via an umbilical 49. The control pod 48 may include one or more control valves (not shown) in communication with the BOPS 42 a,u,b for operation thereof. Each control valve may include an electric or hydraulic actuator in communication with the umbilical 49. The umbilical 49 may include one or more hydraulic or electric control conduit/cables for the actuators. The accumulators 44 may store pressurized hydraulic fluid for operating the BOPS 42 a,u,b. Additionally, the accumulators 44 may be used for operating one or more of the other components of the PCA 1 p. The umbilical 49 may further include hydraulic, electric, and/or optic control conduit/cables for operating various functions of the PCA 1 p. The rig controller may operate the PCA 1 p via the umbilical 49 and the control pod 48.

A lower end of the booster line 27 may be connected to a branch of the flow cross 41 u by a shutoff valve 45 a. A booster manifold may also connect to the booster line lower end and have a prong connected to a respective branch of each flow cross 41 m,b. Shutoff valves 45 b,c may be disposed in respective prongs of the booster manifold. Alternatively, a separate kill line (not shown) may be connected to the branches of the flow crosses 41 m,b instead of the booster manifold. An upper end of the booster line 27 may be connected to an outlet of a booster pump (not shown). A lower end of the choke line 28 may have prongs connected to respective second branches of the flow crosses 41 m,b. Shutoff valves 45 d,e may be disposed in respective prongs of the choke line lower end.

A pressure sensor 47 a may be connected to a second branch of the upper flow cross 41 u. Pressure sensors 47 b,c may be connected to the choke line prongs between respective shutoff valves 45 d,e and respective flow cross second branches. Each pressure sensor 47 a-c may be in data communication with the control pod 48. The lines 27, 28 and umbilical 49 may extend between the MODU 1 m and the PCA 1 p by being fastened along the riser 25. Alternatively, the umbilical 49 may extend to the MODU 1 m separately from the riser 25. Each shutoff valve 45 a-e may be automated and have a hydraulic actuator (not shown) operable by the control pod 48 via fluid communication with a respective umbilical conduit or the LMRP accumulators 44. Alternatively, the valve actuators may be electrical or pneumatic.

Once the drill string 10 has been deployed, the mud pump 30 may pump the drilling fluid 14 d from the transfer line 16, through the header 17 e (via open valves 18 f,h), standpipe 17 p and to the Kelly hose 17 h. The drilling fluid 14 d may flow from the Kelly hose 17 h, through the top drive 5 (via the top drive inlet 5 i) and into the drill string 10. The drilling fluid 14 d may flow down through the drill string 10 and exit the drill bit 12, where the fluid may circulate the cuttings away from the bit and carry the cuttings up an annulus 56 formed between an inner surface of the casing 52 or wellbore 55 and the outer surface of the drill string 10. The returns 14 r may flow through the annulus 56 to the wellhead 50. The returns 14 r may continue from the wellhead 50 and into the riser 25 via the PCA 1 p. The returns 14 r may flow up the riser 25 to the diverter 21. The returns 14 r may flow into the diverter return line 29 via the diverter outlet. The returns 14 r may continue through the diverter return line 29 to the shale shaker 33 and be processed thereby to remove the cuttings, thereby completing a cycle. As the drilling fluid 14 d and returns 14 r circulate, the drill string 10 may be rotated 13 by the top drive 5 and lowered by the traveling block 6, thereby extending the wellbore 55 into the lower formation 54 b.

The drilling fluid 14 d may include a base liquid. The base liquid may be base oil, water, brine, seawater, or a water/oil emulsion. The base oil may be diesel, kerosene, naphtha, mineral oil, or synthetic oil. The drilling fluid 14 d may further include solids dissolved or suspended in the base liquid, such as organophilic clay, lignite, and/or asphalt, thereby forming a mud. The wash fluid 14 w may be any of the base liquids.

FIGS. 4A-4C illustrate removal of a stand 10 s from a drill string 10 of the drilling system 1. Should an unstable zone in the lower formation 54 b be encountered, the drilling system 1 may be shifted into managed pressure mode. As part of the shift to managed pressure mode, the docking station 26 may be shifted from idle mode to active mode by retrieving the protective sleeve 61 and replacing the protective sleeve with the bearing assembly 70.

To retrieve the protective sleeve 61, drilling may be halted by stopping advancement and rotation 13 of the top drive 5 and removing weight from the drill bit 12. The drawworks 9 may be operated to raise the top drive 5 and drill string 10 until a top stand 10 t of the drill string 10 is above the rig floor 4, thereby also pulling the drill bit 12 from a bottom of the wellbore 55. A spider 80 may then be operated to engage an adjacent stand 10 a of the drill string 10, thereby longitudinally supporting the drill string 10 from the rig floor 4. The backup wrench arm actuator may be operated to lower the backup wrench tong to a position adjacent a top coupling of the top stand 10 t. The backup wrench tong actuator may then be operated to engage the backup wrench tong with the top coupling of the top stand 10 t. The backup wrench arm actuator may then be operated as a second thread compensator and the top drive motor 5 m operated to loosen and spin the connection between the quill 5 q and the top stand 10 t.

Once the connection between the quill 5 q and the top stand 10 t has been unscrewed, the top drive 5 may then be raised until the elevator 5 e is proximate to a top of the top stand 10 t. The elevator 5 e may be opened (or already open) and the link-tilt operated to swing the elevator into engagement with the top coupling of the top stand 10 t. The elevator 5 e may then be closed to securely grip the top stand 10 t. A drive tong 81 d may be engaged with a bottom coupling of the top stand 10 t and a backup tong 81 b may be engaged with a coupling of the adjacent stand 10 a. The first top drive thread compensator may be operated to accommodate longitudinal movement of the threaded connection between the top stand 10 t and the adjacent stand 10 a. The drive tong 81 d may then be operated to loosen the connection between the top stand 10 t and the adjacent stand 10 a. Once the connection has been loosened, the drive tong 81 d may be disengaged from the top stand 10 t and a spinner (not shown) may be engaged with the top stand 10 t and operated to spin the connection between the top stand and adjacent stand 10 a.

Once the connection between the stands 10 a,t has been unscrewed, the top drive 5 and top stand 10 t may then be raised and the link-tilt and extender 5 x operated to swing the top stand 10 t into a pipe rack of the drilling rig 1 r. The elevator 5 e may be opened to release the top stand 10 t into the pipe rack. The top drive 5 may then be realigned with the drill string 10 and lowered until the quill 5 q engages a top coupling of the adjacent stand 10 a. The top drive motor 5 m may then spin the connection between the quill 5 q and adjacent stand 10 a and the tongs 81 b,d may then be used to tighten the connection. The spider 80 may then be operated to release the drill string 10 and the top drive 5 may raise the adjacent stand 10 a to a height above the rig floor 4. The process may then be repeated until enough stands 10 s (i.e., one to five stands) have been removed from the drill string 10 to deploy the PSRT 83 using the remaining drill string 10. The drill bit 12 may remain in the wellbore 55 during deployment of the PSRT 83.

FIGS. 5A-5D illustrate addition of the PSRT 83 to the drill string 10. FIGS. 5E-5G illustrate removal of the protective sleeve 61 from the docking station 26 using the PSRT 83. The PSRT 83 may be preassembled with one or more joints of drill pipe 10 p to form a stand 82. The preassembly may be done using the OSB or top drive 5. The top drive 5 may then be raised until the elevator 5 e is proximate to a top of the stand 82. The elevator 5 e may be opened (or already open), engaged with the stand 82 and closed to securely grip the stand. The top drive 5 and stand 82 may then be raised and the link-tilt operated to swing the stand into alignment with the drill string 10. The top drive 5 and stand 82 may be lowered and a bottom coupling of the PSRT 83 stabbed into the top coupling of the drill string 10.

The top drive first thread compensator my again be operated and a spinner (not shown) may be engage with the stand 82 and operated to spin the connection between the stand 82 and the drill string 10. The drive tong 81 d may be engaged with the bottom coupling and the backup tong 81 b may still be engaged with the top coupling of the drill string 10. The drive tong 81 d may then be operated to tighten the connection between the stand 82 and the drill string 10. Once the connection has been tightened, the tongs 81 d,b may be disengaged. The elevator 5 e may be partially opened to release the stand 82 and the top drive 5 lowered relative to the stand. The backup wrench arm actuator may be operated to lower the backup wrench tong to a position adjacent a top coupling of the stand 82. The backup wrench tong actuator may then be operated to engage the backup wrench tong with the top coupling of the stand 82, the elevator 5 e may be fully opened, and the link-tilt operated to clear the elevator. The arm actuator may then be operated as the second thread compensator and the top drive motor 5 m operated to spin and tighten the connection between the quill 5 q and the stand 82.

The spider 80 may then be operated to release the drill string 10. The top drive 5 and the drill string 10 (with assembled stand 82) may be lowered until a top coupling of the stand 82 is adjacent the rig floor. One or more additional stands 10 s may be added to the drill string until the PSRT 83 arrives at the docking station 26. The lugs 85 f may be engaged with the J-slots, the PSRT 83 lowered to move the lugs along the J-slots, rotated across the J-slots by the top drive 5, and then raised to seat the lugs at a closed end of the J-slots. The latch piston 63 p may then be operated by supplying hydraulic fluid from the HPU 32 h and manifold 32 m to the latch chamber via the RCD umbilical 19 u, thereby moving the piston 63 p clear from latch dogs 63 d so that the dogs may be pushed radially outward by removal of the sleeve 61. The drill string 10 may then be raised by removing stands 10 s until the PSRT 83 and latched protective sleeve reach the rig floor 4. The PSRT 83 and protective sleeve 61 may then be disassembled from the drill string 10.

FIG. 6 illustrates stabbing of a bearing assembly running tool (BART) 90 and jetting tool into the bearing assembly 70 to form a running assembly 97. The bearing assembly 70 may include a catch sleeve 71, one or more strippers 72, 73, and a bearing pack 74. Each stripper 72, 73 may include a gland 72 g or retainer 73 r and a seal 72 s, 73 s.

Each stripper seal 72 s, 73 s may be directional and oriented to seal against drill pipe 10 p in response to higher pressure in the riser 25 than the UMRP 20. Each stripper seal 72 s, 73 s may have a conical shape for fluid pressure to act against a respective tapered surface thereof, thereby generating sealing pressure against the drill pipe 10 p. Each stripper seal 72 s, 73 s may have an inner diameter slightly less than a pipe diameter of the drill pipe 10 p to form an interference fit therebetween. Each stripper seal 72 s, 73 s may be flexible enough to accommodate and seal against threaded couplings of the drill pipe 10 p having a larger tool joint diameter. The drill pipe 10 p may be received through a bore of the bearing assembly 70 so that the stripper seals 72 s, 73 s may engage the drill pipe 10 p. The stripper seals 72 s, 73 s may provide a desired barrier in the riser 25 either when the drill pipe 10 p is stationary or rotating.

The catch sleeve 71 may have a landing shoulder formed at an outer surface thereof, a catch profile formed in an outer surface thereof, and may carry one or more seals on an outer surface thereof. Engagement of the latch dogs 63 d with the catch sleeve 71 may connect the bearing assembly 70 to the docking station 26. The gland 72 g may have a landing shoulder formed in an inner surface thereof and a catch profile formed in an inner surface thereof for retrieval by the BART 90. The bearing pack 74 may support the strippers 72, 73 from the catch sleeve 71 such that the strippers may rotate relative to the docking station 26. The bearing pack 74 may include one or more radial bearings, one or more thrust bearings, and a self contained lubricant system. The bearing pack 74 may be disposed between the strippers 72, 73 and be housed in and connected to the catch sleeve 71, such as by a threaded connection and/or fasteners.

Alternatively, the bearing assembly 70 may have a separate docking station seal assembly. Alternatively, an active seal RCD may be used. Alternatively, the RCD receiver may be an annular blowout preventer instead of or in addition to the docking station 26.

The BART 90 may include a mandrel 91 and a latch 92. The mandrel 91 may have couplings formed at each longitudinal end thereof, such as a threaded pin formed at a lower end thereof and a threaded box formed at an upper end thereof, for assembly as part of the drill string 10. The mandrel 91 may further have a landing shoulder 93 b formed in an outer surface thereof for seating against the gland shoulder. The latch 92 may include an actuator, such as a piston 92 p, one or more (two shown) fasteners, such as dogs 92 d, a head 92 h, and a body 92 b. The head 92 h may have a shoulder in engagement with a mating shoulder of the body 92 b. The head 92 h and body 92 b may be connected to the mandrel 91, such as by entrapment between an upper shoulder 93 u of the mandrel 91 and a fastener, such as threaded nut 92 n engaged with a threaded outer surface of the mandrel 91.

A piston chamber may be formed between the head 92 h, body 92 b and mandrel 91. The latch body 92 b may have openings formed through a wall thereof for receiving the respective dogs 92 d. The latch piston 92 p may be disposed in the chamber and the piston 92 p, head 92 h, and mandrel 91 may carry seals isolating an upper portion of the chamber from a lower portion of the chamber. A cam surface may be formed on an outer surface of the piston 92 p for radially displacing the dogs 92 d. Fluid passages may be formed through the body 92 b and head 92 h and may provide fluid communication between respective fluid ports and respective portions of the chamber for selective operation of the piston 92 p. A control line 87 may have fluid conduits and may provide fluid communication between the fluid ports and a pneumatic manifold 95 m controlled by a second control console 95 c. The pneumatic manifold 95 m may also be connected to a compressed air supply 95 p of the MODU 1 m.

Alternatively, the latch 92 may include a spring instead of or in addition to one of the fluid ports. Alternatively, the gland 72 g may have a latch profile similar to the protective sleeve latch profile and the BART 90 may have lugs similar to the PSRT. Alternatively, the protective sleeve 61 may have a second catch profile similar to the gland catch profile and the PSRT 83 may have a latch similar to the BART latch 92.

In order to deploy the bearing assembly 70, the running assembly 97 may be assembled using the OSB or top drive 5. The running assembly 97 may include the bearing assembly 70, the BART 90, the jetting tool 100, and a starter mandrel 99. The running assembly 97 may be assembled by connecting the shoe 99 to the jetting tool 100 and connecting the jetting tool to the BART 90. The interconnected mandrel 99, jetting tool 100, and BART 90 may then be stabbed into the bearing assembly 70. The starter mandrel 99 may gradually spread the stripper seals 72 s, 73 s to avoid damage thereto. Once the mandrel shoulder 93 b lands onto the gland shoulder (FIG. 7E), the latch piston 92 p may then be operated by supplying compressed air from the supply 95 p and pneumatic manifold 95 m to the latch chamber via the control line 87, thereby radially moving the latch dogs 63 d outward to engage the gland catch profile of the bearing assembly 70. Once the bearing assembly 70 has been latched to the BART 90, the starter mandrel 99 may be removed from the running assembly 97. Once the running assembly 97 (minus the mandrel 99) has been connected together, it may be racked for receipt by the top drive 5. The control line 87 may be temporarily disconnected to facilitate addition of the running assembly to the drill string 10.

FIGS. 7A-7D illustrate addition of the running assembly 97 to the drill string 10. FIG. 7E illustrates washing of the docking station latch 63 using the jetting tool 100. FIGS. 7F and 7G illustrate installation of the bearing assembly 70 into the docking station 26 using the BART 90. The running assembly 97 may then be assembled as part of the drill string 10 in a similar fashion as discussed above for the PSRT stand 82.

Once the running assembly 97 has been added to the drill string 10, the spider 80 may then be operated to release the drill string 10. The top drive 5 and the drill string 10 may be lowered until a top coupling of the BART 90 is adjacent the rig floor 4. The control line 87 may be reconnected to the BART 87 and one or more additional stands 10 s may be added to the drill string 10 until the jetting tool 100 arrives at the docking station latch 63. The wash pump 38 may then be operated to inject the wash fluid 14 w down the drill string 10 to the jetting tool 100. The jetting tool 100 may discharge the wash fluid 14 w into the latch 63 to flush any debris therefrom which may otherwise obstruct landing of the bearing assembly 70. The wash fluid 14 w and entrained debris may return to the MODU 1 m via the UMRP 20 and be discharged at the diverter outlet to the shaker 33. The drill string 10 may be reciprocated during washing of the latch 63.

Once the latch 63 has been washed, the drill string 10 may be further lowered until the landing shoulder of the catch sleeve 71 seats onto the landing shoulder of the latch body 63 b. The latch piston 63 p may then be operated by supplying hydraulic fluid from the HPU 32 h and manifold 32 m to the latch chamber via the RCD umbilical 19 u, thereby radially moving the latch dogs 63 d inward to engage the catch profile of the catch sleeve 71.

The latch piston 92 p may then be operated by supplying compressed air from the supply 95 p and pneumatic manifold 95 m to the latch chamber via the control line 87, thereby moving the piston 92 p clear from latch dogs 92 d so that the dogs may be pushed radially outward by removal of the BART 90. Once the bearing assembly 70 has been latched to the docking station 26, the drill string 10 may then be raised by removing stands 10 s until the BART 90 and jetting tool 100 reach the rig floor 4. The BART 90 and jetting tool 100 may then be disassembled from the drill string 10.

FIGS. 8A and 8B illustrates the offshore drilling system 1 in a managed pressure drilling mode. Also as part of the shift to managed pressure mode, a managed pressure return spool 125 may be connected to the RCD return line 19 r and the bypass return spool 36 r. The managed pressure return spool 125 may include a returns pressure sensor 126, a returns choke 127, and a returns flow meter 128. A managed pressure supply spool 130 may also be connected to the supply bypass spool 36 s. The managed pressure supply spool 130 may include a supply pressure sensor 131 and a supply flow meter 132. Each pressure sensor 126, 131 may be in data communication with a second PLC 135. The returns pressure sensor 126 may be operable to measure backpressure exerted by the returns choke 127. The supply pressure sensor 131 may be operable to measure standpipe pressure.

The returns flow meter 128 may be a mass flow meter, such as a Coriolis flow meter, and may be in data communication with the second PLC 135. The returns flow meter 128 may be connected in the spool 125 downstream of the returns choke 127 and may be operable to measure a flow rate of the returns 14 r. The supply flow meter 132 may be a volumetric flow meter, such as a Venturi flow meter. The supply flow meter 132 may be operable to measure a flow rate of drilling fluid 14 d supplied by the mud pump 30 to the drill string 10 via the top drive 5 (via open valves 18 d-f). The second PLC 135 may receive a density measurement of the drilling fluid 14 d from a mud blender (not shown) to determine a mass flow rate of the drilling fluid. Alternatively, the supply flow meter 132 may be a mass flow meter.

Additionally, a degassing spool (not shown) may be connected to a second return bypass spool (not shown). The degassing spool may include automated shutoff valves at each end, a mud-gas separator (MGS), and a gas detector. A first end of the degassing spool may be connected to the return spool between the returns flow meter and the shaker 33 and a second end of the degasser spool may be connected to an inlet of the shaker. The gas detector may include a probe having a membrane for sampling gas from the returns 14 r, a gas chromatograph, and a carrier system for delivering the gas sample to the chromatograph. The MGS may include an inlet and a liquid outlet assembled as part of the degassing spool and a gas outlet connected to a flare or a gas storage vessel.

During managed pressure drilling, the second PLC 135 may utilize the flow meters 128, 132 to perform a mass balance between the drilling fluid 14 d injected into the drill string 10 by the mud pump 30 and returns 14 r received from the RCD 60. In response to incongruity in the mass balance, the second PLC 135 may take remedial action such as tightening the choke 127 in response to a kick of formation fluid and loosening the choke in response to loss of the returns and/or activating the degassing spool. The spools 125, 130 may also be installed before retrieving the protective sleeve 61 and/or before deployment of the bearing assembly 70 and flow from the wash pump 38 may be routed through the supply spool 130 (via open valves 18 g,e,d). The second PLC may 135 perform the mass balance to ensure that any surging or swabbing of the lower formation 54 b by the BHA 10 b being present in the wellbore 55 does not cause a formation fluid influx or return fluid loss to/from the lower formation. If such a well control event is detected while the jetting sub 100 is assembled with the drill string 10, then the jetting sub 100 may be shifted to the well control mode.

Once the spools 125, 130 have been installed and the RCD 60 has been shifted, drilling may recommence in the managed pressure mode. The RCD 60 may divert the returns 14 r into the RCD return line 19 r and through the managed pressure return spool 125 to the shaker 33. As part of the shift to managed pressure mode, a density of the drilling fluid 14 d may be reduced to correspond to a pore pressure gradient of the lower formation 54 b.

Drilling in managed pressured mode may continue until the lower formation 54 b has been drilled to total depth. Alternatively, only the unstable zone of the lower formation 54 b may be drilled in managed pressure mode and then the drilling system 1 switched back into overbalanced mode to drill the rest of the lower formation. To shift the drilling system 1 back to overbalanced mode, the BART 90 may be reassembled as part of the drill string 10 (while the BHA 10 b is located in the wellbore 55), deployed to the bearing assembly 70, and operated to retrieve the bearing assembly from the docking station 26. As mentioned above, the bottom assembly (minus the shoe) may then be assembled as part of the drill string 10 and deployed until the jetting tool 100 reaches the docking station 26. The docking station 26 may then be washed using the jetting tool 100 and the protective sleeve 61 then reinstalled in the docking station 26 using the PSRT 83 and the latch 63. The bottom assembly may then be retrieved and disassembled from the drill string 10 so drilling in overbalanced mode may recommence.

Alternatively, the second PLC 135 and spools 125, 130 may be omitted and the RCD return line 19 r connected to a rig choke (not shown) for applying back pressure. Alternatively, the second PLC 135 and spools 125, 130 may be omitted and the RCD return line 19 r connected directly to the bypass return spool 36 r for continuing overbalanced drilling. Alternatively, the second PLC 135 and spools 125, 130 may be omitted and the RCD return line 19 r may remain closed for proceeding with pressurized mudcap drilling. Any of these alternatives may be used to drill the lower formation 54 b to total depth or only through the unstable zone.

Alternatively, the bearing assembly 70 may be deployed for other operations besides drilling the wellbore 55, such as for running a casing or liner string into the wellbore and the jetting sub and BART may then be assembled as part of a second work string to deploy the casing or liner string. Alternatively, the jetting sub 100 may also be used for other washing operations, such as: cleaning a downhole tubular string, such as a casing, liner, or production tubing string; cleaning an interior of a blowout preventer; cleaning an interior of a wellhead; cleaning an interior of another riser package component; or cleaning a catch profile of a subsea production tree.

While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow. 

1. A jetting tool, comprising: a tubular housing having: couplings formed at each longitudinal end thereof, and one or more ports formed through a wall thereof and in fluid communication with an upper portion of a bore of the housing; and a valve mechanism isolating the housing bore upper portion from a lower portion thereof in a closed position and operable to an open position where the valve mechanism provides fluid communication between the housing bore portions.
 2. The jetting tool of claim 1, wherein the housing ports include one or more upwardly inclined ports, one or more radial ports, and one or more downwardly inclined ports.
 3. The jetting tool of claim 1, wherein: the valve mechanism comprises a piston disposed in the housing bore, and the piston has: a sleeve, a solid nose, and one or more ports formed through a wall of the piston sleeve and in fluid communication with the housing bore upper portion.
 4. The jetting tool of claim 3, wherein the piston ports are downwardly inclined.
 5. The jetting tool of claim 3, wherein: the housing further has a seal receptacle formed in an inner surface of the housing, and the valve mechanism further comprises seals straddling the piston ports and engaged with the seal receptacle in the closed position.
 6. The jetting tool of claim 3, wherein: the valve mechanism further comprises a fastener restraining the piston in the closed position, and the fastener is operable to release the piston in response to fluid pressure in the housing bore upper portion exceeding a threshold pressure.
 7. The jetting tool of claim 6, wherein: the piston is downwardly movable relative to the housing once released by the fastener, the jetting sub further comprises a stop connected to the housing and operable to prevent upward movement of the piston in the closed position, thereby bidirectionally closing the valve mechanism.
 8. The jetting tool of claim 6, wherein the fastener is a shear ring.
 9. A running assembly for deploying a bearing assembly to a receiver, comprising: the jetting tool of claim 1; and a running tool for carrying the bearing assembly and connected to the jetting tool.
 10. A method for washing an interior of a component, comprising: deploying the jetting tool of claim 1 to the component using a tubular string; and pumping wash fluid down the tubular string to the jetting tool, wherein the housing ports impinge the washing fluid against the interior of the component.
 11. A method for deploying a bearing assembly to a receiver, comprising: deploying a running assembly to the receiver, the running assembly comprising: the bearing assembly, a running tool carrying the bearing assembly, and a jetting tool connected to the running tool; washing an inner surface of the receiver using the jetting tool; latching the bearing assembly to the washed inner surface of the receiver; and releasing the bearing assembly from the running tool.
 12. The method of claim 11, wherein: the running assembly is deployed by assembling the tools as part of a tubular string, and a bottom of the tubular string is disposed in a wellbore while the tools are assembled as part thereof.
 13. The method of claim 12, further comprising: monitoring an exposed formation adjacent to the wellbore for instability; and shifting the jetting tool to a well control mode in response to detection of the instability.
 14. The method of claim 13, wherein: the inner surface is washed by pumping wash fluid down the tubular string to the jetting tool using a wash pump, and the jetting tool is shifted by pumping a second fluid down the tubular string to the jetting tool using a mud pump.
 15. The method of claim 13, wherein the formation is monitored by: measuring a flow rate of the injected fluid; measuring a flow rate of returning fluid; and comparing the flow rates.
 16. The method of claim 12, wherein: the tubular string is a drill string, and the tools are assembled as part of a drill string while a drill bit thereof is disposed in a wellbore.
 17. The method of claim 16, further comprising drilling the wellbore after releasing the bearing assembly by rotating the drill bit while injecting drilling fluid through the drill string and lowering the drill string.
 18. The method of claim 11, wherein the receiver is part of an upper marine riser package.
 19. The method of claim 11, further comprising: connecting the jetting tool and the running tool; stabbing the connected tools into the bearing assembly; and latching the bearing assembly to the running tool; 